CORPORATE PRESENTATION. December 2018

Transcription

1 CORPORATE PRESENTATION December 2018

2 BUILDING A FULL CYCLE E&P COMPANY Key License Areas Founded in 2010 by AOG AOG previously established, developed and sold Addax Petroleum March 2016 strategic investment by Zeg Oil and Gas, a Kurdistan Region of Iraq based company Current Ownership: AOG 65%, Zeg Oil 21%, Other 14% Appraisal and development of three oil fields in the Hawler license area (Kurdistan Region of Iraq) 122 MMbbl 2P Oil Reserves (1) with Future Net Revenue (2) of $704 million Average gross (100%) oil production of 10,000 bbl/d in October 2018 (Q3 2018: 7,200 bbl/d) with planned drilling in remainder of 2018 and 2019 expected to increase production Exploration offshore Senegal / Guinea-Bissau 3D seismic data interpretation and prospect ranking in advanced stages with exploration drilling to follow 11 prospects identified with unrisked gross (100%) prospective oil resources of 4.3 billion barrels (risked: 490 MMbbl) (3) TSX listed (ticker: OXC) 1) Gross (working interest) proved plus probable oil reserves as at December 31, Gross refers to volumes before applicable PSC deductions. 2) After-tax net present value of related future net revenue using forecast prices and costs assumed by NSAI and a 10% discount rate as at December 31, Gross proved plus probable oil reserves estimates used to calculate future net revenue are estimated based on economically recoverable volumes within the development/exploitation period specified in the production sharing contract or fiscal regime applicable to each license area. The estimated values disclosed do not represent fair market value. 3) The prospective oil resources data is based upon evaluations by NSAI, and the classification of such resources as prospective oil resources by NSAI, with effective date as at December 31, Prospective oil resources estimates are volumetric estimates prior to economic calculations. 2

3 HAWLER LICENSE (KURDISTAN REGION OF IRAQ) Gross (2) Proved Plus Probable Oil Reserves Future Net Revenue (3) 100% Working Interest Discovery: Oct 2013 Discovery: Feb 2013 Currently producing Field (MMbbl) (MMbbl) (US$MM) Demir Dagh Cretaceous Demir Dagh Jurassic 4 3 Discovery: Mar 2014 Currently producing Discovery: Dec 2013 Currently producing Wells Discovery Completed Appraisal Zey Gawra Cretaceous Banan East Cretaceous Banan West Cretaceous Total Working Interests 65% Oryx Petroleum (Operator) 20% KEPCO (Kurdistan Regional Government) 15% KNOC (Korean National Oil Corporation) (1) The oil reserves, contingent resources and prospective resources data is based upon an evaluation by NSAI with effective date as at December 31, See material change report dated February 15, 2018 filed on SEDAR. (2) Gross refers to volumes before applicable PSC deductions. (3) After-tax net present value of related future net revenue using forecast prices and costs assumed by NSAI and a 10% discount rate as at December 31, The estimated values disclosed do not represent fair market value. See material change report dated February 15, 2018 filed on SEDAR. Unrisked 2C Gross (100%) contingent Oil Resources - Development Pending of 83 MMbbl (Risked: 73 MMbbl) Appraisal / Exploration potential Unrisked Gross 2C (100%) contingent Oil Resources - Development Unclarified of 145 MMbbl (Risked: 100 MMbbl) Unrisked Best Estimate Gross (100%) Prospective Oil Resources of 161 MMbbl (Risked: 6 MMbbl) Four discoveries with production from the Demir Dagh, Zey Gawra and Banan fields (10,000 bbl/d in October 2018) 3

4 HAWLER LICENSE: FIELD OVERVIEW Banan (Tertiary) Two wells successfully completed as producers with additional drilling planned in 2019 Medium grade crude (27º API average) No reserves booked as of 31 December 2017 with bookings expected as of December 31, 2018 Banan (Cretaceous) Two wells drilled to date with one producing Medium grade crude similar to Demir Dagh Cretaceous (22º API) Matrix and fracture porosity Drilling of two wells planned in 2019 Gross (100%) 2P Oil Reserves: 64 MMbbl (1) AAS-2 AAS-1 BAN-4 BAN-2 BAN-3 Banan 211 km 2 BAN-1 Ain Al-Safra 220 km 2 Demir Dagh 197 km 2 Relinquished Area 850 km 2 DD-5 DD-2 DD-10&11 DD-1 DD-7 DD-4&6 DD-8 DD-3&9 Ain Al Safra Two wells drilled with one tested Testing of AAS-2 targeting Jurassic and Triassic planned in 2019 No reserves booked at 31 December 2017 Demir Dagh (Cretaceous) Two wells currently producing Medium grade crude (24º API average) with very small quantities of gas and H 2 S Matrix and fracture porosity Further efforts to bring Demir Dagh-8 well online in December and one short radius sidetrack planned in 2019 Gross (100%) 2P Oil Reserves: 86 MMbbl (1) Zey Gawra (Cretaceous) Five wells drilled to date with three currently producing Light sweet crude (35º API) Matrix and fracture porosity Gross (100%) 2P Oil Reserves: 33 MMbbl (1) Zey Gawra 160 km 2 ZAB-1 ZAB-1 ST ZEG-1 ZEG-2 ZEG-3 ZEG-4 Demir Dagh (Jurassic) One producing well for most of 2016 but shut-in in December 2016 Light crude with gas and H 2 S treatment required Fracture porosity only Gross (100%) 2P Oil Reserves: 4 MMbbl (1) Zey Gawra (Tertiary) ZAB-1 re-entry in late 2016 unsuccessful but sidetrack planned in 2019 No reserves booked at 31 December 2017 Tertiary & Cretaceous Reservoirs Jurassic Reservoirs Possible Triassic Reservoirs (1) As at December 31, 2017 per evaluation conducted by Netherland Sewell & Associates, Inc. ( NSAI ). See Material Change Report dated February 15, 2018 filed on SEDAR. Demir Dagh and Zey Gawra producing from Cretaceous, with Banan producing from both the Cretaceous and Tertiary 4

5 DEMIR DAGH FIELD APPRAISAL AND DEVELOPMENT DD-11 DD-2 DD-10 BAN-1 DD-5 DD-7 DD-6 DD-8 DD-4 DD-9 DD-3 Cretaceous map Ten wells drilled to date Two deep wells to evaluate all reservoirs (DD-2 & 3) Eight shallow wells appraising Cretaceous (DD-4, 5, 6, 7, 8, 9, 10 & 11) Vertical / deviated well designs Six wells completed for production with two wells currently producing DD-2, 4, 6, 7 & 10 completed in Cretaceous DD-3 completed in Jurassic DD-2 and DD-3 shut-in due to high water production DD-4 and DD-7 shut-in due to marginal production levels relative to operating costs Efforts to bring re-completed DD-8 well in Cretaceous online as a producer planned in December 2018 Short radius sidetrack of DD-5 also planned in

6 ZEY GAWRA DISCOVERY AND EARLY APPRAISAL NW SE ZEG-1 discovery in the Cretaceous in 2013 Bakhtiari - Fars Contingent Resources Reserves 33 MMbbl Gross (100%) Proved Plus Probable Oil Reserves (1) Light sweet crude (35º API) Matrix porosity similar to Demir Dagh Pila Spi Avanah - Khurmala Kolosh ZAB-1-ST ZEG-1-ST Higher recovery rates than Demir Dagh Shiranish Qamchuqa Sarmord - Garagu Najmah - Sargelu Alan Mus Adaiyah Butmah Triassic ZEG-1 ST, ZAB-1 ST, ZEG-2, ZEG-3 and ZEG-4 successfully completed as producers in Cretaceous reservoir in late 2016, mid-2017, Q1 2018, Q and Q respectively ZEG-1 ZAB-1 ST and ZEG-2 shut-in ZEG-4 recently brought on production ZAB-1 re-entry in Tertiary reservoir concluded in late 2016 but unable to be completed as a producer in that reservoir (1) As at December 31,

7 ZEY GAWRA APPRAISAL & EARLY PRODUCTION ZAB-1ST ZAB-1 Two wells planned in 2019 ZEG-2 well targeting Cretaceous drilled and completed as a producer in Q Shut in in Q due to water production (lack of isolation from water) ZEG-2 ZEG-1 ZEG-3H ZEG-4H ZEG-3 and ZEG-4 wells targeting Cretaceous drilled in Q and Q3 / Q4 2018, respectively on extended well test Horizontal well design enabled isolation of the producing interval from overlying gas and underlying water in the reservoir Two wells planned for 2019 Sidetrack of ZEG-2 targeting Cretaceous seeking better isolation of producing interval Second sidetrack attempt of ZAB-1 targeting Tertiary 7

8 BANAN DISCOVERY AND EARLY APPRAISAL S BAN-2 N Two wells drilled in 2014 BAN-1 (Drill Stem Test) Bakhtiari - Fars Contingent Resources Reserves BAN-2 (no Drill Stem Test) Pila Spi Gercus - Sinjar Kolosh Both wells confirmed oil in Cretaceous reservoir (Reserves) Shiranish Kometan Qamchuqa Sarmord - Garagu Najmah Medium grade crude similar to Demir Dagh Cretaceous (~20-25 API) Mus - Adayiah - Butmah Matrix and fracture porosity Triassic Data collected during drilling of BAN-2 indicated presence of oil column in Tertiary reservoir (Contingent Resources) BAN-2 BAN-1 Interpretation of data is that Banan is actually two fields separated by a fault (Banan West and Banan East) Pilaspi map 8

9 BANAN APPRAISAL AND EARLY PRODUCTION BAN-3 and BAN-4 wells targeting Tertiary drilled in Q2 & Q respectively and producing on extended well test BAN-2 BAN-4 BAN-5 Average 26 API and 4% sulphur Oil reserves expected to be booked at year end 2018 for the first time BAN-3 BAN-2 well in the Cretaceous successfully completed and placed on extended test in late July 2018 Additional drilling planned in 2019 Two wells targeting Tertiary reservoir with one well to be used as a surveillance well Two wells targeting Cretaceous reservoir 9

10 AIN AL SAFRA Depth TVDSS (m) South Upr Fars 0 AAS-1&2 North Contingent Resources Prospective Resources Gross (100%) (MMbbls) (1) 84 Unrisked Oil Reserves Contingent Oil Resources (2) Prospective Oil Resources 1P 2P 3P 1C 2C 3C Low Best High Pila Spi Tertiary Cretaceous Shiranish Qamchuqa Jurassic Triassic TOTALS Najmah Alan Mus-Adayiah 3000 Butmah Kurra Chine 5km AAS-1 AAS-2 Fracture network October 2013 discovery in the Lower Jurassic Average flow rates of 675 bbl/d and 850 bbl/d of oil using two choke sizes (16/64 and 20/64 ) over 8 hour flow periods (3) Well performance impaired by heavy mud rising during tests Heavy oil AAS-2 appraisal well spudded March 2014 Targeting Jurassic and Triassic reservoirs Drilling completed but unable to be tested due to security developments Positive observations during drilling in Triassic Testing of AAS-2 planned in 2019 (1) As at December 31, Gross refers to reserves and resources before applicable PSC deductions (2) Classified as Development Unclarified at December 31, 2017 (3) DST in the Alan and Mus formations. 10

11 HAWLER PRODUCTION FACILITIES Facilities with processing capacity of 40,000 bbl/d at Demir Dagh Two trains to accommodate both crude oil with and without H 2 S treatment requirements ~1km tie-in pipeline from production facilities to KRI-Turkey export pipeline 25,000 bbl of storage capacity, and 19,000 bbl/d unloading capacity Truck Loading Station (TLS) at Demir Dagh Initial leased processing facilities installed at Zey Gawra in Q and at Banan in Q2 2018, with trucking to Demir Dagh for export pipeline entry More permanent solutions contemplate pipeline transport back to facilities at Demir Dagh for processing and export 11

12 KURDISTAN REGION: SUPPLY DYNAMICS ITP KRI - Turkey 40 & 46 pipelines, 600 & 900 Mbbl/d capacity (1) 24/36 oil pipeline, 700 Mbbl/d capacity To Ceyhan Export Sales: Via Turkey by KRI - Turkey pipeline Recent KRI exports of oil ~400,000 bbl/d Payments from the KRG to oil exporters largely current since September 2015 and now based on Production Sharing Contracts Realisation referenced to international prices Domestic Sales: Limited demand (1) Iraq portion of ITP currently non-operational Oryx Petroleum is currently exporting all production by pipeline 12

13 HAWLER NEAR TERM NETBACKS Illustrative Netback ($/bbl) Contractor Netback Realised Price $50.00 $60.00 $70.00 Royalties 10% (5.00) (6.00) (7.00) Net revenue Cost oil 40% Realised Prices (Export via pipeline): Brent less $7.88/bbl transport / location discount with adjustment for API gravity and sulphur content Contractor Profit oil and Oryx Petroleum capacity building payment assumes R factor <1 Profit oil Contractor share 28% Government share 72% Total Contractor (Cost + Profit oil) Less: Opex (1) (7.00) (7.00) (7.00) Contractor Netback Oryx Petroleum Netback Revenue 65% Less: Royalties & Government share of Profit oil 65% (15.89) (19.07) (22.24) Less: Capacity Payment (2) (0.74) (0.88) (1.03) Normalised Opex to be achieved as production increases and processing / transport infrastructure ~$8/ bbl+ at current production levels Opex and Capex carries Oryx Petroleum carries 20% KRG share Oryx Petroleum carries KRG capex up to $300 million Recoverable from KRG share of cost oil Less: Opex (4) 85% (5.95) (5.95) (5.95) Plus: Carry Recovery (3) Oryx Petroleum After-tax Netback (1) Assumes gross (100%) production of 7,000-8,000 bbl/d (2) 15% of Oryx Petroleum Share of Profit oil (3) Government share of cost oil (4) Assumes $7.50/bbl 13

14 AGC CENTRAL (SENEGAL / GUINEA BISSAU) 3,150 km 2 licence area in water depths of 100-1,500m Carbonate edge play type similar to SNE-1 discovery identified from seismic data 750 km 2 of seismic obligation in initial 3- year exploration phase 1,921 km 2 3D Seismic survey and fast track processing completed in early 2017 Full processing with interpretation largely completed with prospect ranking in final stages 11 prospects identified with gross unrisked (100%) best estimate prospective resources of 4.3 billion barrels (risked 490 MMbbl) (1) 80% Oryx Petroleum (Operator) 20% AGC Two well work commitment prior to October 2020 Prospect selection, environmental impact assessment and well engineering expected in 2019 with drilling to follow Significant light oil potential in an area with a working petroleum system and recent discoveries in adjoining areas (1) As at December 31, 2017 per evaluation conducted by Netherland Sewell & Associates, Inc. ( NSAI ). See Material Change Report dated February 15,

15 AGC CENTRAL: SEISMIC ACQUISITION, PROCESSING & INTERPRETATION SNE A missing piece along the Albian / Aptian shelf margin acquired in 2016 / 2017 Significant light oil potential in an area with a working petroleum system TOP ALBIAN SUBCROP NEW 3D DOME FLORE 1,921 km 2 3D Volume Data owner / licensor - GeoPartners Ltd. Data acquisition by BGP Inc. / CNPC Data processed by DownUnder GeoSolutions Detailed Reconnaissance Study by Lyme Bay Consulting Quantitative Interpretation by RSI Geophysical SINAPA 15

16 AGC CENTRAL: PLAY TYPES PLAY TYPES 1) Maastrichtian clastic play 2) Santonian - clastic play 3) Albian / L. Cenomanian clastic play (SNE analogue) 4) Albian / Aptian carbonate / clastic play AGC Central 3D (2017)

17 AGC CENTRAL: INITIAL INTERPRETATION OF SEISMIC DATA W E LOWER SENONIAN UNCONFORMITY AGC Central Risk Assessment Play Type Reservoir Trap Source Seal Maastrichtian Clastics Low High Low (Albian) Medium Santonian Clastics Medium Medium Low (Turonian) Medium Albian / L. Cenomanian Clastics Medium Low Low (Turonian & Albian) Low Albian / Aptian Carbonates Medium Low Low (Albian) Low 17

18 RECENT FINANCIAL PERFORMANCE Q1 Q2 Q3 Average Daily Gross (100%) Production (bbl/d) 3,300 3,800 4,400 7,200 Realised Oil Price ($/bbl) Oryx Petroleum Revenue ($MM) Operating Cost per Barrel Field Netback (1) ($/bbl) Oryx Petroleum Netback (2) ($/bbl) Operating Funds Flow (3) ($MM) (5.4) ) Field Netback is a non-ifrs measure that represents the Group s working interest share of oil sales net of the Group s working interest share of royalties, the Group s working interest share of operating expenses and the Group s working interest share of taxes. Management believes that Field Netback is a useful supplemental measure to analyse operating performance and provides an indication of the results generated by the Group s principal business activities prior to the consideration of production sharing contract and joint operating agreement financing characteristics, and other income and expenses. Field Netback does not have a standard meaning under IFRS and may not be comparable to similar measures used by other companies. 2) Oryx Petroleum Netback is a non-ifrs measure that represents Field Netbacks adjusted to reflect the impact of carried costs incurred and recovered through the sale of cost oil during the reporting period. Management believes that Oryx Petroleum Netback is a useful supplemental measure to analyse the net cash impact of the Group s principal business activities prior to the consideration of other income and expenses. Oryx Petroleum Netback does not have a standard meaning under IFRS and may not be comparable to similar measures used by other companies. 3) Operating Funds Flow is a non-ifrs measure that represents cash generated from operating activities before changes in non-cash assets and liabilities. The term Operating Funds Flow should not be considered an alternative to or more meaningful than cash flow from operating activities as determined in accordance with IFRS. Management considers Operating Funds Flow to be a key measure as it demonstrates the Group s ability to generate the cash flow necessary to fund future growth through capital investment. Operating Funds Flow does not have any standardised meaning prescribed by IFRS and may not be comparable to similar measures used by other companies. In previous disclosure, Operating Funds Flow was referred to as Operating Cash Flow. 18

19 2019 CAPITAL EXPENDITURE BUDGET Location License / Field / Activity 2019 Budget Kurdistan Region Hawler $ millions Banan - Drilling 16 Zey Gawra - Drilling 6 Demir Dagh - Drilling 3 Ain Al Safra - Drilling 2 Facilities 11 Other (2) 2 Total Hawler 41 West Africa AGC Central 11 Capex Total (1) 52 Note: 1) The above table excludes license acquisition costs. Totals in rows and columns may not add-up due to rounding 2) Other is comprised primarily of studies and license maintenance costs Hawler Banan Drilling Two new wells targeting the Banan Cretaceous reservoir Two new wells targeting Tertiary reservoir one of which will be used as a surveillance well Zey Gawra Drilling Sidetrack of ZEG-2 well targeting Cretaceous reservoir Sidetrack of ZAB-1 well targeting Tertiary reservoir Demir Dagh Drilling Short radius sidetrack of Demir Dagh-5 targeting Cretaceous reservoir Ain Al Safra Drilling Test of AAS-2 well targeting Jurassic and Triassic reservoirs Facilities Pipeline from Banan field to Hawler processing facilities at Demir Dagh Flowlines and field infrastructure required to support new wells AGC Central Drilling preparations, PSC costs 19

20 KEY BALANCE SHEET ITEMS (SEPTEMBER 30, 2018) AND LIQUIDITY OUTLOOK AOG Credit Facility $81 million balance of principal plus accrued interest Interest payable in shares of OXC until July 2019 then payable in cash Currently scheduled to mature in July 2020 (subject to TSX approval) Contingent Consideration Payable to vendor of Hawler license area upon a second commercial discovery Recent agreement to amend pending final execution $86 million balance of principal plus accrued interest $11.4 Million payment pending Remainder payable (contingent) in annual instalments on September 30 of if second commercial discovery declared before September 30, 2019 Interim Credit Facility $7.5 Million available to be drawn prior to December 31, 2018 with repayment required prior to March 2019 Liquidity Outlook Cash on hand at September 30, 2018 ($17.0 million), expected net revenues from sales, proceeds from sale of Haute Mer B interest, and, will allow Oryx Petroleum to fund planned cash expenditures and meet obligations through the end of 2019 Borrowings available under Interim Credit Facility 20

21 POSITIONED FOR GROWTH IN 2019 AND BEYOND Production Ramp-up in the Kurdistan Region of Iraq expected to continue October 2018 and Q Gross (100%) average oil production of 10,000 bbl/d and 7,200 bbl/d, respectively Regular revenue payments for oil exports paid through August 2018 Nine additional wells planned to be drilled, worked over or tested before the end of 2019 Significant Potential Resource Upside in AGC Central license area offshore Senegal / Guinea-Bissau Based on initial interpretation of 3D seismic 11 oil prospects identified with gross unrisked (100%) best estimate prospective resources of 4.3 billion barrels (risked 490 MMbbl) (1) Prospect selection in final stages; a well engineering and environmental impact assessment planned in 2019 with drilling to follow Improved financial performance and liquidity position Supportive major shareholders (1) As at December 31, 2017 per evaluation conducted by Netherland Sewell & Associates, Inc. ( NSAI ). See Material Change Report dated February 15,

22 DISCLAIMER This document has been prepared by Oryx Petroleum Corporation Limited ( Oryx Petroleum or the Corporation ) for information purposes only. This document should be read in conjunction with the annual information form of Oryx Petroleum dated March 23, 2018 (the AIF ). Additional information about Oryx Petroleum is available on its website at and Oryx Petroleum s profile at CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS Statements that are not reported financial results or other historical information are forward-looking information within the meaning of applicable Canadian securities laws and forward-looking statements within the meaning of applicable United States securities laws (collectively, forward-looking statements ). This presentation includes forward-looking statements regarding Oryx Petroleum and the industry in which it operates, including statements about, among other things, exploration and drilling activities, expectations, beliefs, plans, future oil prices, business and acquisition strategies, opportunities, objectives, prospects, assumptions, including those related to trends, prospects, future events and performance. Sentences and phrases containing or modified by words such as anticipate, plan, continue, estimate, intend, expect, may, will, project, predict, potential, targets, projects, is designed to, strategy, should, believe and similar expressions, and the negative of such expressions, are not historical facts and are intended to identify forwardlooking statements. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. Forward-looking statements should not be read as guarantees of future events, future performance or results, and will not necessarily be accurate indicators of the times at, or by which, such events, performance or results will be achieved, if achieved at all. Forward-looking statements are based on information available at the time and/or management s expectations with respect to future events that involve a number of risks and uncertainties, any of which could cause actual results to differ materially from those expressed in or implied by the forward-looking statements. The factors described under the heading Risk Factors in the AIF provide examples of the risks, uncertainties and events that may cause Oryx Petroleum s actual results to differ materially from the expectations it describes in its forward-looking statements. Readers should be aware that the occurrence of the events described in such risk factors could have an adverse effect on, among other things, Oryx Petroleum s business, prospects, operations, results of operations and financial condition. Specific forward-looking statements contained in this presentation include, among others, statements, management s beliefs, expectations or intentions regarding the following: the ability of each of the Corporation and its partners to fund ongoing exploration and meet their respective financing and carry obligations with respect to the license areas of Oryx Petroleum; the performance characteristics and discovery potential of Oryx Petroleum s properties; the Corporation s expectations of current and future production levels; exploration work plans, conceptual development and marketing plans; the reserve and resource potential of Oryx Petroleum s license areas; the political, economic, regulatory and business stability of the jurisdictions in which Oryx Petroleum operates; export pipeline options and export capacity; the Corporation s re-forecasted capital expenditure program and the Corporation s expectations regarding the use of existing capital, its ability to raise capital, develop reserves and resources and to add reserves and resources through exploration, acquisitions and development; the amount, nature, timing and effects of the Corporation s capital expenditures; the Corporation s plans for drilling wells and chance of success; the Corporation s plans for completion or acquisition of seismic data; market prices and supply and demand fundamentals for oil and other commodities; timing and amount of the Corporation s potential future production, forecasts of capital expenditures, net revenues, future development plans and the sources of financing thereof; the Corporation s operating and other costs and expenses; business strategies and plans of management; anticipated benefits and enhanced shareholder value resulting from prospect development and acquisitions; and oil reserves and resources quantities and the discounted present value of future net cash flows from these reserves and resources. Readers are cautioned that the foregoing list of forward-looking statements should not be construed as being exhaustive. In making the forward-looking statements in this presentation, the Corporation has made assumptions regarding: timing and results of exploration activities; the enforceability of the Corporation s production sharing contracts and risk exploration contracts; treatment under the fiscal terms of production sharing contracts, risk exploration contracts, governmental regulatory regimes and royalty laws; the timing and terms of government approvals and the timing and terms of any renewal or extension of any of the Corporation s license areas; the cost of expenditures to be made by Oryx Petroleum; future crude oil prices and prices realised by Oryx Petroleum on oil production sold; the amount of oil production sold domestically in the Kurdistan Region and the amount of oil production sold as export; oil from the Kurdistan Region refining capacity in the local jurisdiction and access to local and international markets for crude oil production; the Corporation s ability to obtain and retain qualified staff and equipment in a timely and cost-efficient manner; the political situation and stability in jurisdictions in which Oryx Petroleum has licenses, including, without limitation, that the recent escalation in violence in Iraq relating to the incursion by the Islamic State in Iraq and Syria (ISIS) will not adversely disrupt the Corporation s production and development activities in the Kurdistan Region; the regulatory, legal and political framework governing the production sharing contracts, risk exploration contracts, royalties, taxes and environmental matters in the jurisdictions in which the Corporation conducts and will conduct its business and the interpretations of applicable laws; the ability to renew its licenses on attractive terms; the Corporation s current and future production levels and the timing and payment mechanism for export oil from the Kurdistan Region; the market for domestic oil sales in the Kurdistan Region and the timing and payment mechanism for such domestic sales in the Kurdistan Region; the applicability of technologies for the recovery and production of the Corporation s oil reserves and resources; ability to gain access to existing facilities or to build necessary facilities to sell oil production; operating costs; availability of equipment and qualified contractors and personnel; future capital expenditures to be made by the Corporation; future sources of funding for the Corporation s capital programs; the Corporation s future debt levels; geological and engineering estimates in respect of the Corporation s reserves and resources; the geography of the areas in which the Corporation is conducting exploration and development activities; the impact of increasing competition on the Corporation; the ability of the Corporation to obtain financing and, if obtained, to obtain acceptable terms; and government/state participation in the Corporation s development activities through the exercise of back-in rights. Forward-looking statements involve significant risks and uncertainties, should not be read as guarantees of future events, performance or results, and will not necessarily be accurate indicators of whether or not such events, performance or results will be achieved. Forwardlooking statements are based on information available at the time and/or management s expectations with respect to future events that involve a number of risks and uncertainties. Any forward-looking statements concerning prospective results of operations, financial position, production, expectations of cash flows and future cash flows that are based upon assumptions about future results, economic conditions and courses of action and are presented for the purpose of providing prospective purchasers with a more complete perspective on Oryx Petroleum s present and planned future operations and such information may not be appropriate for other purposes and actual results may differ materially from those anticipated in such forward-looking statements. Actual results could differ materially from those anticipated in or implied by any forward-looking statements, including without limitation, as a result of the risk factors, which are described in detail under Risk Factors in the AIF. Readers should reference the factors discussed under the heading Risk Factors in the AIF. The forward-looking statements included in this presentation are expressly qualified by this cautionary statement and readers are cautioned that any forward-looking statement speaks only as of the date of this presentation. The Corporation does not undertake any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by applicable securities laws. If the Corporation does update one or more forward-looking statements, it is not obligated to, and no inference should be drawn that it will, make additional updates with respect thereto or with respect to other forward-looking statements. 22

23 DISCLAIMER RESERVES AND RESOURCES ADVISORY The reserves and resources and associated future net revenue information presented herein are estimates only. In general, estimates of oil reserves and resources and the future net revenue therefrom are based upon forward-looking statements and a number of variable factors and assumptions, such as production rates, ultimate reserve recovery, timing and amount of capital expenditures, ability to transport production, marketability of oil, royalty rates, the assumed effects of regulation by governmental and other regulatory agencies and future operating costs, all of which may vary materially from actual results, and for resources, additional variable factors and assumptions such as discovery and commerciality. For those reasons, estimates of the oil reserves and resources attributable to any particular group of properties, as well as the classification of such reserves and resources (based on risk of recovery) and estimates of future net revenues associated with such reserves and resources prepared by different engineers (or by the same engineers at different times) may vary. The actual reserves and resources of Oryx Petroleum may be greater or less than those estimated and such variation may be material. In addition, Oryx Petroleum s actual production, revenues, development, capital and operating expenditures, as applicable, with respect to its reserves and resources will vary from estimates thereof and such variations could be material. Any activities undertaken by Oryx Petroleum to develop or permit the reclassification of its reserves and resources will be subject to the terms of the applicable contractual arrangement. Statements relating to net present value, future net revenues, reserves and resources are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions (including, without limitation, pricing assumptions), that the reserves and resources described exist in the quantities predicted or estimated, and can be profitably produced in the future. Readers should refer to the AIF for information regarding the assumptions related to the reserves and resources reported herein. There is no assurance that forecast price and cost assumptions will be attained and variances could be material. Proved oil reserves are those reserves which are most certain to be recovered. There is at least a 90% probability that the quantities actually recovered will equal or exceed the estimated proved oil reserves. Probable oil reserves are those additional reserves that are less certain to be recovered than proved oil reserves. There is at least a 50% probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable oil reserves. Possible oil reserves are those additional reserves that are less certain to be recovered than probable oil reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of estimated proved plus probable plus possible oil reserves. Contingent oil resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political, and regulatory matters, or a lack of markets. Contingent oil resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery and development and may be sub classified based on project maturity. Contingent oil resources entail additional commercial risk than reserves. There is no certainty that it will be commercially viable to produce any portion of the contingent oil resources. Moreover, the volumes of contingent oil resources reported herein are sensitive to economic assumptions, including capital and operating costs and commodity pricing. Prospective oil resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective oil resources have both an associated chance of discovery and a chance of development. Prospective oil resources entail more commercial and exploration risks than those relating to oil reserves and contingent oil resources. The risked prospective oil resources reported in this presentation are risked resources that have been risked for chance of discovery, for chance of development. If a discovery is made, there is no certainty that itwill be developed or, if itis developed, there is no certainty as to the timing or cost of such development. The reserves estimates and evaluation and resource estimates and evaluation contained herein are derived from the NSAI Report which was prepared with reference to NI relying on the COGE Handbook definitions. Reserves and resources provided herein are as at December 31, 2017 and are only valid as of such date. The estimates of reserves and resources and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and resources and future net revenue for all properties, due to the effects of aggregation. The estimated future net revenues contained herein are valid only as at December 31, 2017 and do not necessarily represent the fair market value of Oryx Petroleum s reserves and resources. As used herein, unless otherwise indicated, gross means, in respect of reserves, resources, production, area, capital expenditures or operating expenses, the total reserves, resources, production, area, capital expenditures or operating expenses, as applicable, attributable to either (i) 100% of the license area, field, prospect or lead; or, (ii) the Corporation s working interest in the license area, field, prospect or lead, as indicated, prior to the deductions specified in the applicable production sharing contract, risk exploration contract or fiscal regime for each license area. In addition to the general advisory language above, the below notes qualify certain reserves and resources volumes and other oil and gas information disclosed in this document: : This volume is an arithmetic sum of multiple estimates of reserves or resources, as applicable, which statistical principles indicate may be misleading as to volumes that may actually be recovered. Readers should give attention to the estimates of individual classes of reserves or resources, as applicable, and appreciate the differing probabilities of recovery associated with each class as explained above. : All field fluid measurements will require laboratory analysis to confirm results and should be considered preliminary until such analysis has been done. The test results are not necessarily indicative of long-term performance or of ultimate recovery. 23

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